Tubing hanger apparatus and wellhead assembly for use in oil and gas wellheads

ABSTRACT

A tubing hanger apparatus includes a tubing hanger with a plurality of segments thereon that engage an annular groove of a tubing head thus preventing the tubing hanger from sliding down a well. The internal diameter wellhead bore is consistent from the master valve downward to the production casing. The tubing hanger has a plurality of annular seals which are expandable after insertion into the tubing head. A plurality of lock screws both expand the seals as well as prevent any further movement of the tubing hanger. The tubing hanger apparatus is situated below a master valve. Thus, coiled tubing or jointed tubing can be run down the well and landed below the master valve. The tubing hanger contains a back pressure valve, thus the master valve can be opened without releasing the formation pressure within the live well.

FIELD OF THE INVENTION

This invention relates generally to tubing hangers for use in oil andgas wellheads.

BACKGROUND OF THE INVENTION

Oil and gas wellheads are a combination of components that preventpressurized ground substances in a well from being released abovegrounds. These components include valves and other components which aremanipulated to control the release of the pressurized ground substances.The wellhead components also serve to hold a combination of casings andtubing in a well through which the pressurized ground substances flow.One such component, a tubing hanger, primarily acts to suspend theweight of a production tubing within a casing of the well. Historically,the tubing hanger is attached to the wellhead by lock screws andadditionally to the tubing below by connectors to ensure the tubing isanchored within the well. The casing having a larger diameter than thetubing, serves as a cylindrical enclosure for the tubing to insertthrough. Once inserted, the tubing can inject or remove the pressurizedground substances.

Because the ground substances are pressurized, a seal is requiredbetween the tubing hanger and a tubing head that surrounds the tubing.This seal is conventionally provided by O ring seals attached to thetubing hanger which engage the tubing head surrounding the tubinghanger. Additionally, wellhead pressure is controlled by a master valvelocated above or below the tubing hanger and by a blowout preventerdevice which rests on top of the wellhead and allows for an additionalvalve to be closed in order to prevent an untimely explosive pressurerelease.

Conventionally, tubing hanger apparatuses utilize a load shoulder withinthe lower portion of the tubing head on which the tubing hanger willland when inserted into the tubing head. This shoulder reduces theinternal diameter of the tubing head to prevent the tubing hanger fromfurther movement down the well. The presence of the load shoulder limitsthe diameter of the bore and thus limits the width of any componentsneeded to be lowered into the well. As such, once the tubing head isinstalled on a well, the internal diameter of any casings or otherobjects placed down the well must be smaller than the internal diameterof the tubing hanger load shoulder. This is problematic as it is limitsthe further utilization of the well.

Tubing hangers used in conventional wellheads utilize O ring sealsconnected to the external circumference of the tubing hanger to providea seal between the tubing hanger and the tubing head. The seal isrequired to maintain pressure below the tubing hanger. The O rings arepre-extruded, therefore, the external diameter of the O ring is greaterthan the external diameter of the tubing hanger body and slightlygreater than the internal diameter of the tubing head. When a tubinghanger is lowered into the tubing head, problems may develop if theexternal surfaces of the O ring seal contact other structures on thewellhead and thus possibly damage or tear the O ring seals. Because theO ring seal extrudes from the tubing hanger, it is prone to being caughton other wellhead surfaces. Although care may be taken to insert thetubing hanger; once an O ring is torn or damaged, the tubing hanger mustbe removed and repaired which is both costly and timely.

In the prior art, a tubing head created by Woodgroup Pressure Control(the “Woodgroup Tubing Head”) incorporates a tubing hanger that is heldin place within the tubing head by a load shoulder and a plurality ofsteel lock screws. The tubing hanger is inserted in the tubing head andcomes to rest on the load shoulder of the tubing head. The hanger isthen locked in place by lock screws. The load shoulder includeddecreases the internal diameter of the tubing head resulting in adecreased internal bore diameter and limits the diameter of any downhole implements to be used. Further, the Woodgroup Tubing Head utilizespre-extruded O ring seals that are prone to damage due to errors intubing hanger insertion.

In conventional oil and gas wellheads a master valve is installed tocontrol the release of pressurized substances within the well. Themaster valve can also be opened to allow further insertion of drillingcomponents down the well. When tubing hangers are connected above themaster valve, coiled tubing or jointed tubing must be inserted throughthe tubing hanger, master valve and into the well. This is problematicas the coiled tubing running through the master valve will prevent theclosing of the master valve as the valve will pinch the tubing uponclosing. Further, accidental closing of the master valve whilstinserting tubing through the master valve will either damage the tubingor the master valve. In addition once the tubing is being run throughthe master valve there is no ability to prevent backflow without firstfreezing the well.

SUMMARY OF THE INVENTION

According to one aspect of the invention, there is provided tubinghanger apparatus for a wellhead. The apparatus comprises a tubing head,a tubing hanger, an engagement segment, and an actuation segment. Thetubing head has a bore with a recess in the bore surface and a shoulderprotruding from the bore surface below the recess. The tubing hanger isinsertable within the tubing head bore, and has an upper end, and alower end connectable to a coiled tubing or jointed tubing string. Thetubing hanger also has between the upper and lower ends: a bore contactsurface for slidably contacting the bore surface, an engagement surfacebelow and laterally recessed from the bore contact surface, and anactuation surface below and laterally recessed from the bore contactsurface. The engagement segment is slidable along the engagement andactuation surfaces of the tubing hanger. The actuation segment isslidable along the actuation surface of the tubing hanger below theengagement segment. The above components are arranged so that when thetubing hanger is located in a locked position in the bore, the actuationsegment contacts the bore shoulder, the engagement segment is locatedonto the engagement surface by the actuation segment and engages thebore recess. This aspect of the invention overcomes one prior artproblem of having a narrower internal diameter of the tubing headbecause of the need for wide load shoulders. As such, a full borewellhead can be provided without substantially decreasing the internaldiameter of the tubing head or casing strings below it. Further, amaster valve can be located above the tubing hanger apparatus having aninternal diameter equal to or greater than that of the production casingattached to the wellhead without reducing the internal diameter of thetubing head.

The bore contact surface, engagement surface and actuation surface canbe annular and extend around the tubing hanger. The actuation andengagement segments can also be annular and be slidable along the tubinghanger. Further, the engagement segment can be expandable wherein theengagement segment is in an unexpanded position when surrounding theactuation surface and in an expanded position when surrounding theengagement surface.

The tubing hanger apparatus can be further comprised of a compressibleannular seal surrounding a sealing surface that is laterally recessedfrom the bore contact surface of the tubing hanger. This compressibleannular seal does not protrude from the bore contact surface whenuncompressed. A seal compressor movable between an uncompressed positionwherein the seal is uncompressed, and a compressed position wherein theseal is compressed and protrudes beyond the bore contact surface tocontact the bore surface when the tubing hanger is inserted inside thebore can also be provided. The seal compressor can be annular andsurrounds the tubing hanger adjacent the seal and is slidable along thetubing hanger between the uncompressed and compressed positions. A sealcompressor engagement means can also be provided to engage the sealcompressor when the tubing hanger is in the locked position and move theseal compressor between compressed and uncompressed positions.

The tubing hanger apparatus can be further equipped with a lock screwoperable to engage the tubing hanger when in the locked position. Spirallocks can be located on the tubing hanger below the actuation andengagement segments and prevent the actuation and engagement segmentsfrom sliding off the tubing hanger.

In another aspect of the invention, a wellhead assembly is providedcomprising a blowout preventer, an adaptor flange connected to theblowout preventer; a master valve connected to the adaptor flange, and atubing hanger apparatus wherein the tubing head is connected to themaster valve. Alternatively, the wellhead assembly can comprise theaddition of a swedge attached at a first end to the tubing head and atop section attached to a second end of the swedge.

Further preferred features of the invention are in the followingdescriptions of illustrative embodiments.

BRIEF DESCRIPTION OF THE DRAWINGS

FIG. 1. is a side view of a conventional wellhead with a master valvelocated below a tubing hanger (PRIOR ART);

FIG. 2. is a schematic cross-sectional side view of a portion of awellhead containing a tubing hanger secured by lock screws (PRIOR ART);

FIG. 3. is a side cross-sectional view of a tubing hanger apparatusaccording to one embodiment of the present invention and comprising atubing hanger in a first position inside a tubing head;

FIG. 4. is a side cross-sectional view of the tubing hanger apparatuscomprising a tubing hanger in a second position in the tubing head;

FIG. 5. is a side cross-sectional view of a portion of the tubing hangerapparatus illustrating a plurality of seals not engaged with the tubinghead in the first position within the tubing head;

FIG. 6. is an expanded side cross-sectional view of the tubing hangerapparatus illustrating a plurality of engaged expanded seals in thesecond position with the tubing head;

FIG. 7. is a side view of a portion of the tubing hanger illustratingthe annular actuation and spring loaded segments and annular spirallocks.

FIG. 8. is an expanded side view of a portion of a wellhead assemblywith a partial cross-sectional view showing the tubing hanger of FIG. 3inside the wellhead, and a blowout preventer located above the tubinghanger apparatus; and

FIG. 9. is a side view of a portion of an alternative form of thewellhead assembly including a top portion above the tubing hangerapparatus.

DETAILED DESCRIPTION OF THE EMBODIMENTS

The prior art as illustrated in FIG. 1 is comprised of a portion of awellhead assembly including a prior art tubing hanger apparatus 2 abovea master valve 4, a bell nipple 7 threadably connected at its upperextremity to said master valve and to a production casing 8 at its lowerextremity. The master valve 4 is attached to prevent backflow when inits closed position. When necessary, for example, to remove liquids fromthe well, a coiled tubing or jointed tubing 10 is run down the wellheadassembly and into a well by a lubricator (not shown) and attached to thelower extremity of the tubing hanger 11. A surface casing 6 surroundsthe production casing and coiled tubing or jointed tubing 10. Because,the coiled tubing or jointed tubing 10 is inserted into a well throughthe master valve 4, there is no ability to close the master valve 4. Assuch, there is no ability to prevent backflow without first freezing thewell. In such assemblies, the master valve 4 is tendered obsolete by thecoiled tubing or jointed tubing 10 running through it and impeding itsability to close.

FIG. 2 illustrates a portion of the Woodgroup Tubing Head which isanother type of prior art tubing hanger apparatus and includes a meansof locking a tubing hanger 11 within a tubing head 13 by utilizing lockscrews 12. Further, this device includes pre-extruded seals 9 which aresusceptible to tearing upon insertion of the tubing hanger 11 into awellhead. When lowering the tubing hanger 11 into the tubing head 13,the pre-extruded seals 9 are susceptible to catching on the wellheadstructures and thus being damaged. Once damaged, the tubing hanger 11must be removed and repaired.

This Woodgroup Tubing Head device is designed to land the tubing hanger11 on a load shoulder 1 within the tubing head 13. This load shoulder 1engages the lower extremity of the tubing hanger 11 thus preventingfurther downward movement of the tubing hanger 11. To accomplish this,the load shoulder 1 must create a narrower internal diameter of thetubing head 13 compared to the internal diameter of the tubing head 13above the load shoulder 1. With the tubing hanger 11 having a greaterexternal diameter than the internal diameter of the tubing head 13 atthe point of the load shoulder 1, the tubing hanger 11 is prevented fromfurther downward movement. Further, the Woodgroup Tubing Head is lockedin place by lock screws 12.

Referring to FIGS. 3-7, in an embodiment of the invention, a tubinghanger apparatus is comprised of a tubing head 14 and a tubing hanger 16located within a bore of the tubing head 14. The tubing hanger 16 has anupper end and a lower end. The tubing hanger 16 has an annular borecontact surface 70 having an outer diameter that is slightly less thanthe bore diameter of the tubing head 14 to allow the tubing hanger 16 tobe lowered into the tubing head 14 bore and be slidable therein.

Below the bore contact surface 70 is an annular engagement surface 72laterally recessed from the bore surface, i.e. has a smaller diameterthan the bore surface. Below the engagement surface is an annularactuation surface 74 that is laterally recessed from the engagementsurface 72, i.e. has a smaller diameter than the engagement surface 72.A sloped shoulder 76 connects the actuation surface 74 to the engagementsurface 72.

An actuation segment 23 is annular and surrounds the tubing hanger 16;particularly, the actuation segment 23 is slidable along the axis of theactuation surface. A spring loaded engagement segment 24 is annular andsurrounds the tubing hanger 16. Particularly, the engagement segment 24is slidable along the axis of both the actuation 74 and engagement 72surfaces.

The actuation segment 23 is annular and has an outer surface with achamfer extending circumferentially along its lower edge. The engagementsegment 24 is also annular and has a chamfer extending circumferentiallyalong its lower and upper edges. The engagement segment is a “c-shaped”spring loaded ring with first and second ends facing each other. Theengagement segment is biased in unexpanded position wherein theengagement segment is in slidable contact with the actuation surface.The engagement segment can be expanded into an expanded position whenslid onto the engagement surface.

Specifically referring to FIGS. 3, 5 and 7, in a first position, thetubing hanger 16 is inserted into the bore of the tubing head 14 but hasnot yet engaged the tubing head 14 or come to rest. At this point theactuation segment 23 approaches an actuation shoulder 25 protruding fromthe bore surface of the tubing head 14 and the engagement segment 24 isresting above the actuation segment 23. The actuation shoulder 25 hassufficient width to engage the actuation segment 23 surrounding thetubing hanger 16 but not sufficient width to engage the tubing hanger 16itself (because the actuation and engagement surfaces are recessed fromthe bore contact surface). This actuation shoulder 25 is unlike loadshoulders 1 in the prior art in that its width is minute when comparedto load shoulders 1 and thus it does not significantly narrow theinternal diameter of the tubing bead 14. Further, the tubing hanger 16does not engage this actuation shoulder 25 directly, rather, only theactuation segment 23 engages this actuation shoulder 25.

Specifically referring to FIGS. 4 and 6, in a second “locked” position,the lower, chamfered surface of the actuation segment 23 engages acorresponding chamfered upper surface of the actuation shoulder 25located within the tubing head 14 and pushes up the actuation segment 23which in turn pushes up the spring loaded segment 24 from the actuationsurface, over the sloped shoulder and onto the engagement surface toengage a groove 26 in the tubing head 14 above the actuation shoulder25. As discussed above, the engagement segment expands when pushed ontothe engagement surface. The groove 26 is an annular channel or recesswith tapered side walls. When the spring loaded segment 24 is engagedwithin the groove 26, the tubing hanger 16 has no ability for downwardmovement. Further, downward movement of the tubing hanger 16 isprevented by the engagement of the upper surface of the spring loadedsegment 24 and the upper surface of the groove 26 and the lower surfaceof the actuation segment 23 engaging the upper surface of the actuationshoulder 25. The weight of the production tubing below the tubing hanger16 provides downward force on the tubing hanger 16 due to the effect ofgravity on the production coiled tubing or jointed tubing 30.

While in the embodiment shown in the Figures the tubing hanger 16 andbore are generally cylindrical, it is within the scope of the inventionfor these components to have other shapes, in which case the respectivebore contact, engagement and actuation surfaces would not be annular.Further, the engagement and actuation segments do not need to beannular, and can instead, blocks that are aligned with the respectiveactuation and engagement surfaces, such that the engagement segment canengage with the groove in the tubing head bore.

Referring again to the embodiment shown in the FIGS. 3-7, the tubinghead 14 including the actuation shoulder 25 and the groove 26 are in oneembodiment made of 4140 alloy steel, but could be made from alternateforms of alloy steel or other material known to a person skilled in theart. The tubing hanger 16 including the actuation segment 23 and springloaded segment 24 are in another embodiment made of 4130 alloy steel.However, these components likewise could be made of other forms of alloysteel or other substances known to one skilled in the art.

Referring particularly to FIGS. 3-7, a plurality of spiral locks 18 arelocated at the top and bottom of the tubing hanger 16. The spiral locks18 are annular and fit within an annular groove 42 in the tubing hanger.The spiral locks 18 prevent the actuation segment 23 and spring loadedsegment 24 from sliding off the tubing hanger 16 when not engaged withthe tubing head 14.

Referring particularly to FIGS. 4, 5 and 8, the tubing head 14 containslaterally extending holes for receiving lock screws 21. The tubinghanger 16 is further secured within the tubing head 14 by three lockscrews 21. These lock screws 21 additionally support the tubing hanger16 within a specific position in the tubing head 14 and prevent upwardmovement of the tubing hanger 16. The lock screws 21 also contribute toseal engagement as discussed in detail below.

Upper and lower compressible annular seals 22, preferably made ofrubber, encircle the tubing hanger 16 along a sealing surface locatedabove the bore contact surface. The seals 22 are separated by a middlering 45 which also encircles and is slidable along the sealing surface.Referring to FIG. 5, when the tubing hanger 16 is in the first position,the seals 22 are not compressed and thus do not expand beyond the borecontact surface of the tubing hanger 16. In this position the seals 22remain flush with the bore contact surface of the tubing hanger 16. Byremaining flush, the seals 22 are not as susceptible to damage uponinsertion into the tubing head 14.

Referring to FIG. 6, when the tubing hanger 16 is in the locked positionand engaged with the tubing head 14, the seals 22 can be expanded suchthat they engage the tubing head 14 and create an annular seal betweenthe tubing hanger 16 and tubing head 14. This seal is accomplished bythe lock screws 21 engaging a top ring 44 located above the upper seal22 on the tubing hanger 16. The top ring 44 is slidably movable in anaxial direction over the tubing hanger surface and has an inner diameterslightly greater than the external diameter of the coiled tubing orjointed tubing 30 that runs through the tubing hanger 16, and an outerdiameter that is slightly less than the internal diameter of the tubinghead 14. Part of the upper surface of the top ring 44 is chamfered tocorrespond to a portion of the distal end of the frusto-conical shapedlock screw 21. The top ring 44 serves as a seal compressor: as the lockscrews 21 engage the top ring 44, the top ring moves downwards tocompress the seals 21, thereby causing the seals to protrude from thebore contact surface and engage the bore surface.

Referring to FIG. 8, a wellhead assembly is comprised of a blowoutpreventer 31 which is flanged attached at its lower extremity to anadaptor flange 55 that is threadably attached at its lower extremity tothe master valve 34 which is then threadably attached at its lowerextremity to the tubing head 14. The blowout preventer 31 prevents thesudden backflow release of pressure from the well. A tubing hangerapparatus as previously described is included in the wellhead assemblybelow the master valve 34. Above the tubing hanger apparatus, a stringof coiled tubing or jointed tubing 30 is centrally fitted through themaster valve 34 and then through a central passage in the tubing hanger16 and inserted into the well. Within the well the coiled tubing orjointed tubing 30 is inserted to a predetermined depth, cut and sealed.The top end of the coiled tubing or jointed tubing 30 string is engagedwith the tubing hanger's 16 lower extremity by a plurality of threadedconnectors 46 located on the inner surface of the tubing hanger's 16central passage. As the coiled tubing or jointed tubing 30 passes theplurality of threaded connectors 46, the threaded connectors 46 engagethe outer surface of the coiled tubing or jointed tubing 30, preventingit from coming loose.

The tubing hanger 16 is further equipped with a back pressure valvethread 20 which allows a back pressure valve to be lubricated andthreaded into the tubing hanger 16. With a tubing hanger 16 containingthe back pressure valve 20 in place in the wellhead, a test port 35 canbe utilized to determine if a proper seal exists between the tubinghanger 16 and tubing head 14. Referring particularly to FIG. 8, a testport 35 is located within the tubing head 14 to allow for fluid to beintroduced below the seals 22 to determine if an annular seal existsbetween the tubing hanger 16 and tubing head 14. Without the ability totest for a proper seal created by the seals 22, lock screws 21 andtubing weight, it would be dangerous to remove the wellhead componentsabove the tubing hanger 16 without the knowledge that the tubing hanger16 is properly engaged and sealed within the tubing head 14.

The lower extremity of the tubing head 14 is threadably attached to abell nipple 36 which is threadably attached at its lower extremity to aproduction casing 29 which is inserted into the well. The bell nipple 36serves as a connection between the production casing 29 and tubing head14. Further, the well is encased with a surface casing 28 whichencircles the production casing 29. The coiled tubing or jointed tubingstring 30 attached at its upper end to the tubing hanger 16 is insertedinto the production casing 29 and ultimately, into the well.

Because this wellhead assembly has a master valve 34 above a tubinghanger 16 apparatus equipped with a backpressure valve 20, the assemblyhas multiple means of preventing backflow from the well. After testingfor a seal utilizing the test port 35 as described above, any pressureabove the tubing hanger 16 apparatus can be bled off and the mastervalve 34 removed or replaced if necessary. Any backpressure will becontained by the backpressure valve 20 within the tubing hangerapparatus. This is necessary for the ability to replace or repair themaster valve 34 or other components above the tubing hanger 16 withoutexposing the operator to the dangerous conditions of a live well oralternatively, having to freeze the well. By having the master valve 34above the tubing hanger 16, there is no tubing running through themaster valve 34 which would impede its removal or may cause accidentaldamage to the coiled tubing or jointed tubing 30 or master valve 34.

In an alternate form of this assembly shown in FIG. 9, and following theremoval of the blowout preventer 31 and master valve 34, a swedge 32 canbe threadably attached at the upper extremity of the tubing head 14 witha top section 25 threadably attached at the upper extremity of theswedge 32 for production purposes. The swedge 32 allows for connectingthe reduced diameter of a top section 25 to the tubing head 14. The topsection 47 may include a flow tee 48 for branching the wellheadassembly, a ball valve 49 for extracting fluids, and/or a needle valve50 for bleeding off pressure, but may include other components thatothers skilled in the art would be aware of. The top section 47 can beattached via the ball valve 49 to a pumping vehicle which can deliverpressure to the coiled tubing or jointed tubing 30 string within thewell in order to remove a plug (not shown) that had been previouslyinserted at the lower extremity of the coiled tubing or jointed tubing30. By removing the plug, pressurized substances are free to move up thecoiled tubing or jointed tubing 30 and out of the wellhead through thetop section 47. It should be recognized that a master valve 34 may alsobe included in this alternate assembly between the swedge 32 and tubinghead 14.

Directional terms “above”, “below”, etc. used are merely intended toassist the reader in understanding the relative positions of thecomponents when the apparatus is in operation. They are not intended, inany manner, to limit the scope of the claims. One of ordinary skill inthe art would recognize other variations, modifications, andalternatives. It should be recognized that, while the present inventionhas been described in relation to the preferred embodiments thereof,those skilled in the art may develop a wide variation of structural andoperational details without departing from the principles of theinvention. Therefore, the appended claims are to be construed to coverall equivalents following within the true scope of spirit of theinvention.

1. A tubing hanger apparatus for a wellhead, comprising: a tubing headhaving a bore with a recess in the bore surface and a shoulderprotruding from the bore surface below the recess; a tubing hangerinsertable within the tubing head bore, the tubing hanger having anupper end, a lower end, connectable to a coiled tubing or jointed tubingstring, and between the upper and lower ends: a bore contact surface forslidably contacting the bore surface, an engagement surface below andlaterally recessed from the bore contact surface, and an actuationsurface below and laterally recessed from the bore contact surface; anengagement segment slidable along the engagement and actuation surfacesof the tubing hanger, an actuation segment slidable along the actuationsurface of the tubing hanger below the engagement segment; wherein whenthe tubing hanger is located in a locked position in the bore, theactuation segment contacts the bore shoulder, the engagement segment islocated onto the engagement surface by the actuation segment and engagesthe bore recess.
 2. A tubing hanger apparatus as claimed in claim 1wherein the bore contact surface, engagement surface, and actuationsurface are annular and extend around the tubing hanger.
 3. A tubinghanger apparatus as claimed in claim 2 wherein the actuation andengagement segments are annular, and are slidable along and surround thetubing hanger.
 4. A tubing hanger apparatus as claimed in claim 3wherein the engagement segment is expandable, wherein the engagementsegment is in an unexpanded position when surrounding the actuationsurface and in an expanded position when surrounding the engagementsurface.
 5. A tubing hanger apparatus as claimed in claim 4 wherein theengagement segment has first and second ends facing each other.
 6. Atubing hanger apparatus as claimed in claim 2 wherein the tubing hangerfurther comprises: a sealing surface above and laterally recessed fromthe bore contact surface; a compressible annular seal surrounding thesealing surface such that the seal does not protrude from the borecontact surface when uncompressed; and a seal compressor movable betweenan uncompressed position wherein the seal is uncompressed, and acompressed position wherein the seal is compressed and protrudes beyondthe bore contact surface to contact the bore surface when the tubinghanger is inserted inside the bore.
 7. A tubing hanger apparatus whereinthe seal compressor is annular and surrounds the tubing hanger adjacentthe seal, the seal compressor being slidable along the tubing hangerbetween the uncompressed and compressed positions.
 8. A tubing hangerapparatus as claimed in claim 7 wherein the tubing head furthercomprises a seal compressor engagement means operable to engage the sealcompressor when the tubing hanger is in the locked position and move theseal compressor between compressed and uncompressed positions.
 9. Atubing hanger apparatus as claimed in claim 1 further comprising a lockscrew operable to engage the tubing hanger when in the locked position.10. A tubing hanger apparatus for a wellhead as claimed in claim 1further comprising an annular spiral lock located on the tubing hangerbelow the actuation and engagement segments and for preventing theactuation and engagement segments from sliding off the tubing hanger.11. The tubing hanger apparatus for a wellhead as claimed in any ofclaims 1 to 10 further comprising a master valve located above thetubing hanger apparatus and having an internal diameter equal to orgreater than that of a production casing attached to the wellheadwithout reducing the internal diameter of the tubing head.
 12. Awellhead assembly comprising: a blowout preventer; an adaptor flangeconnected to the blowout preventer; a master valve connected to theadaptor flange; and a tubing hanger apparatus as claimed in claim 1wherein the tubing head is connected to the master valve.
 13. A wellheadassembly as claimed in claim 12 further comprising: the addition of aswedge attached at a first end to the tubing head and a top sectionattached to a second end of the swedge.